1. Field of the Invention
The present invention relates to a method and apparatus for storage of solar energy within an artificial or synthetic geothermal environment. The present invention also relates to the creation and utilization of thermal reservoirs for the synthetic geothermal storage of solar energy, to secondary and tertiary oil recovery, and to the use of those thermal reservoirs for water distillation and continual, or sustained, energy production.
2. Description of the Related Art
Various methods of the production of energy from solar energy are known. In connection with the production of energy from the sun, methods have been developed to concentrate solar heat. These methods include solar flux furnaces (1,000° C. to 5,500° C.), solar towers (400° C. to 1,100° C.), and solar trough technologies (100° C. to nearly 550° C.), all of which are known in the prior art.
One difficulty associated with reliance on solar energy is the variability associated with this type of energy production. As those skilled in the art will readily appreciate, solar energy is dependent upon daylight time, variable cloud conditions and seasonal solar incidence. For this reason, solar energy cannot be relied upon to deliver base load or peak load electrical power.
With respect to the recovery of oil and gas from oil and gas fields, these fields typically are found in porous and permeable reservoir beds. Initial recovery rates of only 30% of oil from oil fields are common. In order to recover the remaining 70% of the oil fuels from these reservoirs, it is often necessary to rely on secondary or tertiary recovery efforts.
One type of secondary or tertiary recovery method that has been developed involves steam injection methods for enhanced recovery of hydrocarbons. In this methodology, steam is introduced (called “steam flooding”) into, for example, an oil reservoir to draw (or force) the oil residuals from the reservoir in which they are located. Steam flooding is considered to be one of the most efficient methods of secondary or tertiary oil recovery.
One problem associated with steam flooding is the creation of the steam required for the process. As would be appreciated by those skilled in the art, the cost of steam generation is quite high. In addition, the steam front introduced into a reservoir initially experiences significant cooling due to heat absorbed by the host rock (i.e., the rock forming the hydrocarbon reservoir). Accordingly, steam flooding is usually limited to low viscosity (i.e., 18 gravity and below) oil deposits in small (i.e., 10 acres or less per well) pro-ration unit fields.
Since steam generation is very cost intensive, requiring significant amounts of natural gas or liquid hydrocarbon combustion to generate the steam, steam flooding of large pro-ration fields (i.e., greater than 20 acres per well) has not been relied upon widely. Simply, the heat lost to the reservoir strata and resultant ineffective thermal drive has been prohibitive to the application of steam flooding under these circumstances.
One benefit of long-term steam flooding in a large pro-ration unit field is the enhanced ultimate recovery of hydrocarbons from the field. However, as noted above, the cost associated with long term steam flooding does not support the use of this method for application to large pro-ration unit fields.
It is also known to use hyper-saline water (brine) to extract residual hydrocarbons from reservoirs. This is known as “water flooding” to distinguish it from steam flooding. Produced hyper-saline water (“water cut”) is a common by-product of oil production. The water cut, which may be considered as “waste water” depending on its chemical composition, routinely is re-injected into porous and permeable strata of non-producing wells (water disposal wells) or is utilized as a driving agent in secondary and tertiary oil field recovery projects. A significant problem with the use of waste water is that waste water is considered an environmental hazard. As a hazard, its disposal is regulated. Moreover, spills of brine waste water require remediation. State and Federal environmental codes mandate approved disposal methods and techniques.
Various methods are known for extracting heat from naturally-occurring geothermal reservoirs. These methods rely upon natural thermally charged igneous sources of geothermal energy. In other words, these sources extract geothermal heat from geothermal sources, or other thermal uses known to those skilled in the art, and convert it into electrical energy.
The concept of extracting heat from deep permeable strata in existing, but depleted, gas reservoirs also has been proposed. (Swift and Erdlac, 1999.) In particular, it has been proposed to introduce water into deep permeable strata to heat the water into steam, which can be used for electrical power generation.
As would be appreciated by those skilled in the art, geothermal production of electricity has been limited to igneous terrains. Permeability of the igneous terrains and a lack of water resources have presented significant obstacles to this type of energy production. Insufficient permeability has proved a particular difficulty in hot dry rock technology where rock with a low thermal conductivity immediately adjacent to induced fracture surfaces is rapidly depleted of its thermal charge.
Heat budget management has also proven a problem in geothermal projects. The capacity to extract heat from a geothermal source often exceeds the natural heat flow within the rocks, resulting in decreased plant efficiency and extinction of associated hydrothermal phenomenon, such as geysers and hot springs. Once a natural geothermal reservoir has been identified, production wells are drilled to extract the geothermal/hydrothermal energy.
Water is used to carry thermal energy out of the reservoir, either through flow of natural hydrothermal reserves or by pumping water into the reservoir through injection wells, circulating the fluid through the reservoir to extraction bore holes. The water flows through the permeable strata, is heated by contact with the hot rock, and then is used to transfer the geothermal heat to the surface, flowing upward through one or more production wells in a pressurized, closed-loop circulating operation, referred to as heat mining.
At the surface, the heat contained in the circulating geothermal fluid is either flashed to steam, directly driving turbines, or is transferred to a second fluid (referred to as a binary working fluid) in a high-pressure heat exchanger of conventional design. Then, the cooled geothermal fluid is re-injected into the geothermal reservoir to be reheated. The second fluid is commonly ammonia, or a mixture of low molecular weight hydrocarbons, such as isobutane (C4H10) or isopentane (C5H12).
Even though the hot pressurized geothermal fluid is relatively benign from a chemical perspective, flashing geothermal fluid into steam at the surface can result in a release to the environment of small amounts of environmentally undesirable dissolved materials such as hydrogen sulfide, boron, arsenic, selenium, mercury, lead, and other trace elements and compounds, which are common to and occur naturally in the igneous or metamorphic host rock.
Equally significant, quantities of silica, chlorides, and carbonates are also typically dissolved in the aqueous geothermal fluid, potentially causing corrosion and undesirable deposits (i.e., scale) on turbine blades and other metallic surfaces in power plants and in heat exchangers.
Water-based geothermal systems generally have a geo-chemically determined, temperature limit controlled by the critical point of water (374° C. and 22 MPa).
As the critical point for water is reached and then surpassed, the enhanced dissolution of silica, followed by retrograde precipitation below 374° C. and 22 MPa, presents a substantial obstacle to operating an igneous geothermal reservoir at higher than the critical temperature. Moreover, these reservoirs occur most commonly in igneous and metamorphic rocks, where silica is present as either a primary or secondary (i.e., fracture filling) mineral. The silica dissolution and re-precipitation problem occurs as the critical temperature for water is passed.
Although drilling systems are capable of reaching rock temperatures in excess of 400° C., concerns about enhanced geothermal interactions arise in water based igneous geothermal energy systems at these temperatures. Specifically, scaling becomes a considerable concern for these environments.
Scaling problems are much reduced in the sedimentary strata encountered in oil provinces. The oil industry has developed methods and technologies to minimize and/or control scaling problems.
In summary, the prior art associated with the production of electricity from solar energy, geothermal energy, and hydrocarbon combustion present specific problems that are, as yet, unaddressed.
There is still a great need for improved methods of delivering low cost live (supercritical) steam for efficient secondary and tertiary hydrocarbon recovery programs, for producing and storing solar energy, and for producing and storing geothermal energy.